Treatment of subsurface hydrocarbon fluid-bearing formations to reduce water production therefrom



United States Patent O TREATMENT OF SUBSURFACE HYDROCARBON FLUID-BEARING FORMATIONS TO REDUCE WATER PRODUCTION THEREFROM Burton B. Sandiford, Placeutla, Califi, assignor to Union Oil Company of California, Los Angeles, Calif., a corporation of California No Dram'ng. Filed Dec. 28, 1965, Ser. No. 517,109

Claims. (Cl. 16633) This application is a continuation-in-part of prior co-' pending application Serial No. 285,216, filed June 4, 1963, and now abandoned.

This invention relates to the treatment of subterranean hydrocarboniferous formations so as to improve the efli ciency of recovery of fluid hydrocarbons therefrom via producing wells traversing such formations. More specifically, the invention relates to methods for decreasing the water/ oil ratio in the total well eflluent, and for increasing the daily production rate of hydrocarbonaceous fluids.

In broad aspect, the invention comprises injecting into the formation, through a producing well, a substantial quantity of an aqueous solution, or sol, of a high molecular weight, water-soluble polyacrylamide (PAM) wherein at least about 8%, but not more than about 70% of the amide groups have been hydrolyzed to carboxylic acid groups. Following injection of the aqueous PAM solution into the formation, the well is then placed back on production, and it is found that, under the same conditions as were employed prior to the treatment, there is a substantial reduction in water/oil ratio of the well efliuent, due primarily to a reduced flow rate of water into the well bore. Moreover, as a result of this decreased water flow rate, there will be, at the same gross production rate, a reduction in fluid level over the pump, with resultant decrease in back pressure on the formation, thus permitting oil to move more rapidly out of the formation into the well bore. Thus, although the immediate effect of the treating process of this invention is to decrease the rate of flow of water into the well bore, a secondary effect of increasing the absolute daily production rate of oil is also obtainable.

As those skilled in the art are Well aware, the production of large amounts of water from oil wells and gas wells constitutes one of the major items of expense in the overall recovery of hydrocarbons therefrom. Many oil wells will produce a gross eflluent comprising 80-90% by volume of water and only 10-20% of oil. Most of the pumping energy is therefore expended in lifting water from the well, and thereafter the eflluent must be put through expensive separation procedures to recover waterfree oil. The remaining foul water constitutes a troublesome and expensive disposal problem. It is therefore highly desirable to decrease the volume of water produced from oil wells and gas wells, this being the major objective of the present invention. But, by decreasing the flow rate of water into the well bore without decreasing the flow rate of oil, another beneficial effect is obtained in that, at a given pumping rate, there will be a lower liquid level over the pump in the well bore, thus reducing back-pressure on the formation, and improving pumping efliciency and net daily oil production.

.I am unable to account with any degree of certainty for the beneficial effects observed herein, but it would appear that such effects are attributable primarily to an actual combining or coating of the mineral particle surfaces in the formation with the PAM treating agent. Production water from wells treated by the process of this invention does not become entirely free of the PAM treating agent for many weeks after the treatment. -It is therefore believed that the said treating agent has some considerable tendency to remain affixed in the formation, either by chemical bonding or electrostatic attraction, to the mineral surfaces defining the pores thereof, and behaves as a surfactant, or perhaps a selective plugging agent, to restrict the flow of water in the formaion without restricting the flow of oil.

The process of this invention is not to be confused with secondary recovery processes, wherein a depleted or partially depleted well is put back into production, or production is improved, by water flooding, or fluid drive techniques. In these latter processes, water or other aqueous media is pumped into one or more injection wells under a pressure sufficient to cause the water to flow outwardly therefrom through the oil-bearing formation towards one or more relatively depleted producing wells. Theoretically, as the water flows through the oilbearing formation the oil contained therein is forced ahead of the advancing water front into the producing wells. It is well known that water alone is relatively inefficient in this flooding technique because the water chooses the path of least resistance, i.e., the strata of highest permeability, and hence travels from the injection well to the producing wells in more or less well defined channels and fails to sweep the oil efficiently from the formation as a whole. Normally, the strata of high est permeability are water-bearing, or at least water-wet, and their permeabilities are higher with respect to water than to other fluids, particularly petroleum, and this condition aggravates the channeling of the sweep fluid.

In US. Patents Nos. 2,827,964, and 3,039,529, it is shown that the aforedescribed water flooding techniques can be materially improved by using as the flooding media, somewhat viscous solutions of partially hydrolyzed PAM-solutions of the same nature as may be employed in the treating process of this invention. US. Patent No. 3,020,953 shows that solutions of completely unhydrolyzed PAM can also be used in water flooding operations. The effect of all of these viscous PAM solutions, hydrolyzed or unhydrolyzed, is to cause the flooding medium to advance through the formation to the producing wells in a more or less plane front rather than in channels through the more permeable strata. beneficial effect of PAM solutions in these flooding techniques thus is believed to rest primarily upon their rheological properties, rather than upon the specific chemical The producing well, in the process of this invention the beneficial effects accrue only while there is a significant amount of treating agent in the formation surrounding the well bore, and they theoretically will terminate when all of the treating agent has been swept from the formation back into the well bore.

US. Patent No. 3,087,543 to Arendt describes a treating process which, in its essential mechanics, is the same as the present process. However, there is no disclosure in the Arendt patent of the 870% hydrolyzed poly-acrylamides required herein. As will be shown hereinafter, this specific class of treating agents has been found to be much more effective in reducing water permeability than the acrylamide-carboxylic acid copolymer disclosed in the Arendt patent.

The PAM treating agents of the present invention are characterized in general by a molecular weight of at least about 200,000 and preferably at least about 1,000,- 000, with at least about 8%, and up to about 70%, preferably up to about 25%, of the amide groups being bydrolyzed to canboxylic groups. A 0.5% by weight aqueous solution of the treating agent should have a viscosity of at least about 4, and preferably at least about 10 centipoises (Ostwald) at 21.5 C. Hydrolysis of the acrylamide polymer is accomplished by reacting the same with sufficient of aqueous alkali, e.g., sodium hydroxide, to hydrolyze between about 8% and 70% of the amide groups present in the polymer molecule. The resulting products consist of a long hydrocanbon chain, the alternate carbon atoms of which bear either amide or carboxylic groups. A number of partially hydrolyzed acrylamide polymers suitable for use herein are commercially available, for example materials marketed by Dow Chemical Company under the trade names Separan NP-ZO or ET-601. Polymers hydrolyzed to an extent greater than about 70% are undesirable in that they have a greater tendency to form precipitates with polyvalent metal ions found in connate (reservoir) waters, with resultant plugging of the formation. Polymers wherein less than about 8% of the amide group have been hydrolyzed are considerably less effective in reducing water permeability, and are hence excluded herein.

The concentration of PAM treating agent in the aqueous solution pumped down the well may vary over a wide range, from about 1 p.p.m. to about 5% by weight. The optimum concentration will depend to a large extent upon the volume of reservoir water with which the treating solution will be diluted in the formation. It is preferred to adjust the concentration of treating agent, and the volume of the aqueous slug injected, so that the concentration of treating agent in the formation waters will be between about 0.01% and 0.5% by weight. It is further preferred that the volume of the aqueous slug injected be between about 0.02% and 5% of the oil volume in the oil recovery area around the given producing well being treated.

In carrying out the process of this invention, conventional injection procedures are employed, i.e., the well to be treated is suitably fitted with packers if required, and the aqueous treating agent is forced down the well bore and out into the reservoir formation by means of conventional pumping equipment (if required) located at the well head. Normally, the injection can be completed in about /2-3 days, after which the well may be substantially immediately placed back on production. The initial well effluent following the treatment is sharply reduced in water/ oil ratio, and production may be continued for several weeks or months with improved oil recovery and reduced water production. Gradually however the wateroil ratio will begin to rise again, and when the ratio reaches an undesirably high level, the well may be again shut in and the treatment repeated to again improve production.

Following a given treatment, the initial production water recovered when the well is placed back on production may be fairly rich in the PAM treating agent. If

desired this portion of the aqueous effiuent may be reused, or employed for treating other wells. As previously noted however, most of the PAM treating agent remains in the formation for long periods of time, and the production water following a given treatment very rapidly declines in PAM concentration, such that reuse is not feasible.

In one mode of operation it is contemplated that the retention of PAM in the formation, and its resultant effectiveness as a treating agent, may be further improved by first treating the formation wit-h a hydrocarbon solvent in order to dissolve out heavy hydrocarbonaceous materials, thus opening up the pores and rendering the mineral surfaces more readily available for contact with the PAM treating agent to be subsequently injected. Suitable solvents include for example pentane, benzene, light aromatic gasoline fractions and the like. Such a pretreatment with hydrocarbon solvent is accomplished by pumping, e.g., about 10-500 barrels of the desired solvent into the formation, and then putting the well back on production for a short time to remove the tar-laden solvent, after which the PAM treating agent is injected.

The process of this invention is designed for treating substantially any type of producing well, either an oil well or a gas well. Such well may be operating under natural flow conditions, or it may be a producing well involved in a secondary recovery operation wherein a flooding medium, or gaseous driving medium, is being injected into an adjacent well. It is contemplated that in such secondary recovery operations, treatment of the producing well will cause the selective diversion of reservoir waters to other wells, or to adjacent aquafer structures, thus reducing the water/ oil ratio in the producing well effluent.

The following examples are cited to illustrate the invention, and to demonstrate the beneficial results obtained, but are not to be construed as limiting in scope.

Example I This example demonstrates the effect of the PAM treating agents in reducing the permeability of oil-bearing formations with respect to water, without reducing the permeability to oil. A Nevada sand pack core (length, 5 inches; diameter, 1%,2-l110h) was mounted in a plastic core holder equipped with pressure fittings on its opposite faces so that desired liquids could be forced lengthwise through the core. The core was first placed in a simulated restored state (as it might exist in an oiland water-bearing formation) by saturating it with mineral oil (viscosity 62 cp.) and water containing 2.3% NaCl.

Upon flooding the restored-state core with water, its permeability with respect to water, K was determined to be 940 md. (millidarcies). The core was then resaturated with mineral oil and its permeability with respect to oil, K was determined to be 2,680 md. The core was then Water-flooded to displace 15% of the recoverable, stock tank oil therefrom. At this point a small slug of a 0.35 weight-percent water solution of an 8l0% hydrolyzed polyacrylamide of about 2,000,000 molecular weight was injected into the core. The slug was equivalent to 8.5% of the undisplaced oil volume. The core was then water flooded to completion of oil recovery; K was found to be only 166 md. On resaturation with mineral oil, K was 2,685 md. Thus, the water permeability decreased from 940 md. to 166 md., while the oil permeability remained essentially unchanged.

Example 11 This example compares the effectiveness as treating agents of various polyacrylamides wherein the amide groups have been hydrolyzed in varying degrees.

Four Nevada 135 sand pack cores were placed in simulated restored state and tested for oil and water permeability as in Example I. Each core was then treated with 14 ml. of a 0.05% aqueous solution of the indicated PAM treating agent, and permeabilities were then again determined, with the following results:

tially improved oil recovery and reduced water production continued for a period of at least about three months.

Core

A B C D Initial Permeabilities, md.:

Water 744 777 743 773 Oil 1, 970 2, 510 2, 440 2, 405 PAM Treating Agent:

Percent Hydrolysis of amide groups 0-1 4-5 8-10 25-35 Av. Mol. Wt -5, 000, 000 1, 000, 000 -2, 000, 000 1, 000,000

Posiaflgeaunent Permeabilities, md.:

er 372 Percent of Initial Water Permeability 50 on 1, 760 Percent of Initial Oil Permeability 89 From the foregoing, it is apparent that the polyacrylamides hydrolyzed to the extent of 8-35 are more than twice as effective in reducing water permeability as compared to polyacrylamides hydrolyzed to the extent of only 05% Example III This example demonstrates the useful effects obtainable by treating a producing well in a flooding operation. A 3 /-inch diameter core from the Caprock Queen field in New Mexico was mounted in plastic and three simulated wells were drilled into the core parallel to the axis thereof, and spaced at equidistant points from each other at the apices of an imaginary isometric triangle. Oil and water was injected simultaneously into one of the simulated wells, A, and efiiuent was recovered from the other two wells, designated as producing wells B and C, and water/ oil ratios of the respective efiiuents were determined. Producing well B was then treated by injecting a slug of the 0.35% aqueous PAM treating solution employed in Example 1, equivalent to about 2% of the pore volume of the core. Producing well C was untreated. Oil-Water injection into well A was then resumed, and water/oil ratios from the producing wells B and C were again determined. The results were as follows:

Since gross production rates from wells B and C were approximately the same, it is clear that treatment of well B caused relatively more water to be diverted to well C.

Example IV This example illustrates the beneficial effects of the invention in an actual field test on a producing Well producing 16 API gravity oil from a depth of about 3,100 feet at a reservoir pressure of about 500 psi. and a temperature of 146 F. This well was producing at an average rate of about 900 b./ d. gross and about 40 b./d. net oil (860 b./ d. water), at a liquid level over the pump of about 515 feet.

For the test, production was suspended for one day, and 500 barrels of a 0.5% solution of the PAM treating agent employed in Example 1 dissolved in fresh water was injected into the well, followed by 200 barrels of fresh water. Upon resuming production the following day, water production was only 600 barrels per day, a reduction of 30%. During the succeeding month, net oil production increased from an average of about 40 b./d. to about 150 b./d. Also the fluid level over the pump fell from about 515 feet to about 350 feet. Substan- Substantially similar beneficial results are obtained when other partially hydrolyzed PAM treating agents within the purview of this invention, and when other contemplated modes of application thereof, are employed in lieu of those illustrated in the foregoing examples. It is therefore not intended that the invention should be limited to the details described above, but broadly as defined in the following claims.

I claim:

1. A method for recovering fluid hydrocarbons from a subterranean formation which is penetrated by a well bore, and for reducing the concomitant production of reservoir water therefrom, which comprises: injecting into said formation through said well bore an aqueous treating solution comprising a minor proportion of a water-soluble, partially hydrolyzed polyacrylamide treating agent having a molecular weight in excess of about 200,000, at least about 8% but not more than about 70% of the amide groups thereof having been hydrolyzed to carboxyl groups, then terminating the injection of said treating agent and thereafter placing the treated well on production.

2. A method as defined in claim 1 wherein said fluid hydrocarbons comprise liquid petroleum.

3. A method as defined in claim 1 wherein said fluid hydrocarbons comprise natural gas.

4. A method as defined in claim 1 wherein sufficient of said polyacrylamide treating agent is injected into said formation to provide a concentration thereof in the reservoir waters of between about 0.01% and 0.5 by weight.

5. A method as defined in claim 1 wherein said partially hydrolyzed polyacrylamide has a molecular Weight in excess of about 1,000,000, at least about 8% but not more than about 25% of the amide groups thereof having been hydrolyzed to carboxyl groups.

6. A method as defined in claim 1 wherein said subterranean formation is treated with an extraneous hydrocarbon solvent to dissolve out heavy hydrocarbonaceous materials prior to said injection of aqueous treating solution.

7. A method for beneficiating oil production from an oil well traversing a subterranean petroleumand waterbearing formation, and wherein said oil well is being pumped at a rate such that there is a substantial liquid level over the pump, so as to increase the daily oil production rate and decrease water production, which comprises: interrupting oil production from said well, injecting down said well and into said formation an aqueous solution comprising a minor proportion of a water-soluble, partially hydrolyzed polyacrylamide treating agent having a molecular weight in excess of about 200,000, at least about 8% but not more than about 70% of the amide groups thereof having been hydrolyzed to carboxyl groups, then terminating the injection of said treating agent, and thereafter placing said well back on production at a pumping rate such that there is a substantial reduction in liquid level over said pump, and recovering from said well a liquid effluent of substantially reduced Water/ oil ratio.

8. A process as defined in claim 7 wherein suflicient of said polyacrylamide treating agent is injected into said formation to provide a concentration thereof in the reservoir waters of between about 0.01% and 0.5% by weight.

9. A process as defined in claim 7 wherein sufficient of said aqueous solution containing polyacrylamide treating agent is injected into said formation to provide a volume thereof equivalent to between about 0.2% and 5% of the oil volume in the oil recovery area adjacent to said well.

References Cited by the Examiner UNITED STATES PATENTS 2,827,964 3/1958 Sandiford et al l669 3,039,529 6/ 1962 McKennon l669 3,087,543 4/1963 Arendt 16-6'30 3,121,462 2/1964 Martin et al. l6629 CHARLES OCONNELL, Primary Examiner.

10. A method as defined in claim 7 wherein said par- 15 NOVOSAD, Assistant Ex ine 

1. A METHOD FOR RECOVERING FLUID HYDROCARBONS FROM A SUBTERRANEAN FORMATION WHICH IS JPENETRATED BY A WELL BORE, AND FOR REDUCING THE CONCOMITANT PRODUCTION OF RESERVOIR WATER THEREFROM, WHICH COMPRISES: INJECTING INTO SAID FORMATION THROUGH SAID WELL BORE AN AQUEOUS TREATING SOLUTION COMPRISING A MINOR PROPORTION OF A WATER-SOLUBLE, PARTIALLY HYDROLYZED POLYACRYLAMIDE TREATING AGENT HAVING A MOLECULAR WEIGHT IN EXCESS OF ABOUT 200,000, AT LEAST ABOUT 8% BUT NOT MORE THAN ABOUT 70% OF THE AMIDE GROUPS THEREOF THAVING BEEN HYDROLYZED TO CARBOXYL GROUPS, THEN TERMINATING THE INJECTION OF SAID TREATING AGENT AND THEREAFTER PLACING THE TREATED WELL ON PRODUCTION. 